Method for correlating well logs

ABSTRACT

The invention relates to a method of correlating two or more overlapping well logs generated by a well logging device which, in use, is positioned in a well and is mounted to an elongate member extending along the well to the surface, movement of the elongate member at the surface controlling movement of the logging device along the well. The method comprises: (a) receiving sets of logging data for two or more spatially overlapping logs generated by the logging device, each set comprising measures of a characteristic of the well at longitudinally spaced positions along the well; (b) receiving measurement data for the period or periods of log generation, the measurement data comprising measurements of the load on the elongate member and measurements of the surface position of the elongate member; and (c) correlating optimising a the sets of logging data by determining an elongate member compliance which corrects the positions of the measured well characteristics. The corrections in step (c) are performed on the basis of a correction function which relates the position of the logging device to at least (i) the measured load on the elongate member, (ii) the measured surface position of the elongate member, and (iii) the compliance of the elongate member.

FIELD OF THE INVENTION

The present invention relates to a method for correlating well logs.

BACKGROUND OF THE INVENTION

Well logging tools are commonly used in well drilling and productionoperations to characterise wells. Such tools may comprise e.g. gamma-rayor electrical resistivity sensors which provide information on thelithology of the rock formation traversed by the well. Most sensors areset up to make measurements at regular time intervals as the loggingtool travels along the well. Thus typically a log produced by a sensorcomprises a series of measurements taken at particular times whichcorrespond to spaced positions along the well. However, a problem ariseswhen the logging tool velocity varies, as the longitudinal spacing ofthe measurement positions also then varies and the resulting log can bedifficult to interpret.

Furthermore, when different logs are produced for the same stretch ofwell by a logging tool having spaced sensors or by the same sensor atdifferent times, it can be difficult properly to match or correlate thefeatures of one log with the features of another because of thevariation in measurement position.

This problem is particularly acute for LWD (Logging While Drilling)operations because the process of drilling generally involves irregulardrill string movements and hence large changes in velocity (and evenreversals of direction) of the logging tool. Thus LWD logging toolvelocity is prone to significantly more variation than the velocity ofe.g. a logging tool or “sonde” controlled by a wireline.

During well drilling it is usually important to be able to determine theposition and/or rate of penetration of the drill bit. However, while themovement of a drill bit is controlled to a significant extent by themovement of the drill string at the well surface which in turn iscontrolled by the hook load applied to the drill string, the precise wayin which these parameters impact on the movement of the drill bit can becomplicated. This is because the apparent compliance of the drill stringis not determined solely by the physical properties and length of thedrill string. Thus a correction needs to be introduced if the surfacemovement of the drill string is to be used to predict the downholemovement of the drill bit.

The apparent compliance of the drill string can be influenced by manyfactors. For example, there is usually significant friction between thestring and the walls of the well, as well as changing thrust loadsexerted on the string. Insofar as these factors can be determined withany precision, they add considerable complexity to the determination ofthe drill string compliance. Inaccuracies, such as calibration problems,wear etc., in the surface draw works system for measuring block heightmay also be complicating factors. Thus mere knowledge of theinstantaneous hook load and the instantaneous velocity of the drillstring at the surface may not supply the well operator with enoughinformation to correct the relative depth and penetration rate of thedrill bit with sufficient accuracy.

In an attempt to overcome this problem, U.S. Pat. No. 4,843,875describes a procedure for measuring drill bit rate of penetration whichassumes that the behaviour of the drill string can be modelled by arelationship of the form:$V_{F} = {V_{S} + {\lambda\frac{\mathbb{d}F}{\mathbb{d}t}}}$where V_(F) is the instantaneous velocity of the drill bit, V_(S) is theinstantaneous velocity of the drill string at the surface, λ is theapparent compliance of the drill string, and dF/dt is the firstderivative with respect to time of the weight F suspended from the hook.

To be fully effective this approach requires a very good hookloadmeasurement—so that not only the hookload but also the rate-of-change ofhookload can be accurately derived. Errors due to friction in the rigapparatus can produce significant errors in the rate-of-change ofhookload.

An alternative procedure, described in U.S. Pat. No. 5,321,982, uses awell tool having at least two logging sensors which are spaced a knowndistance apart in the direction of movement of the tool. By matching thelogs produced by the sensors it is possible to determine theinstantaneous velocity (i.e. rate of penetration) of the tool. However,because drill bit penetration rates generally do not vary smoothly, thisapproach has little predictive capacity for drilling operations.

U.S. Pat. No. 5,522,260 discloses a procedure for performing depthcorrection on a logging tool having two spaced sensors in which the toolis provided with an accelerometer. In this procedure, the tool velocitydetermined by correlating the sensor logs is combined with the toolvelocity determined by the accelerometer to produce a depth correctionfor the tool. However, this procedure is not particularly suitable forLWD operations because LWD logging tools are not usually provided withaccelerometers.

SUMMARY OF THE INVENTION

At least in part, therefore, the present invention aims to alleviate oravoid some of the aforementioned problems.

In general terms the present invention provides a method for correlatingwell logs, in which data from two or more overlapping logs generated bya well logging device and a model for the apparent compliance of theelongate member (e.g. the drill string) which controls the position ofthe logging device are combined to correlate the log data.

Thus a first aspect of the present invention provides a method ofcorrecting depth of logging data measured by a logging system mounted onan elongate member extending through a wellbore to the surface. Themethod comprises the following steps.

Receiving sets of logging data for two or more spatially overlappinglogs generated by the logging system, each set comprising measures of acharacteristic associated with the wellbore at longitudinally spacedpositions along the wellbore.

Receiving measurement data for the period or periods of log generation,the measurement data comprising measurements of the load on the elongatemember and measurements of the surface position of the elongate member.

Determining a compliance parameter representing the compliance of theelongate member by comparing at least two of the sets of logging datadepth corrected using a plurality of values for the complianceparameter, and selecting a value for the compliance parameter thatyields a high degree of consistency between the at least two sets oflogging data.

And correcting the depth of at least one set of logging data measuredusing the logging system, using a correction function which relates theposition of the logging system to at least (i) the measured load on theelongate member, (ii) the measured surface position of the elongatemember, and (iii) the selected compliance parameter of the elongatemember.

Typically the elongate member compliance is an apparent compliance.Furthermore, typically either or each of the position of the loggingmember and the surface position of the elongate member is a relativeposition.

Although, the correlation of the logs may be an end in itself, thecompliance thus-determined can also be used to correct the depth of thelogging device. Therefore, preferably the method comprises the furtherstep of obtaining a corrected depth (or relative depth) for the loggingdevice on the basis of the compliance. The corrected depth is typicallyobtained by applying the compliance to the correction function. However,this does not exclude the possibility that the compliance may beapplied, e.g. to a different correction function, to obtain thecorrected depth.

The degree of correlation of the logs may be determined by a suitableobjective correlation function, such as a scalar correlation coefficientin the case where two logs are correlated or a cross correlation matrixin the case where more than two logs are correlated.

Typically the step of correlating the sets of logging data involves anoptimisation procedure so that the elongate member compliance which bestcorrects the positions of the measured well characteristics isdetermined.

For example, the process of correlation may involve iteratively testingdifferent values for the compliance until the compliance which producesthe highest degree of correlation between the logs is established. Suchtesting may be performed numerically. For example, a Monte-Carlo orsimulated annealing procedure may be used to obtain a provisionaloptimal compliance which may then be further refined by a localtechnique such as gradient descent. Other suitable techniques are knownto the skilled person.

The measured load on the elongate member can be e.g. a surface load or adownhole load. For example, when the elongate member is a drill stringthe measured load can be the hookload or the load near the drill-bit(i.e. the weight-on-bit).

An advantage of the method is that log correlation and optionally depthcorrection can be performed without accelerometer data from the loggingdevice. Hence the method is particularly suited for use in LWDoperations, and in preferred embodiments the elongate member is a drillstring. The optimal compliance can then be used to correct the depth ofthe drill bit. For example, during LWD operations the logging device anddrill bit are usually sufficiently close such that the compliance of theintervening drill string can be neglected. Thus the logging device andthe drill bit can be considered as being rigidly connected and thecorrection of the depth of the logging device then effectively alsocorrects the depth of the drill bit.

However, the method has more general applicability and may also be usede.g. to provide log correlation and optionally depth correction for awireline sonde (in which case the elongate member would be the wirelinecable).

Furthermore, on the assumption that the compliance determined for theelongate member is valid at times outside the period or periods overwhich the logs are generated, the (or another) correction function canbe used to make depth correction predictions outside these periods. Thisis in contrast to the procedure described in U.S. Pat. No. 5,321,982,which only allowed instantaneous tool velocities to be determined.

In simple embodiments, the correction function may be similar to thatused in U.S. Pat. No. 4,843,875. The compliance then takes a singlenumerical value. Alternatively, however, more complex functions may beused e.g. allowing different numerical values for the compliancedepending on the type of drilling operation (for example rotating orsliding), and/or allowing the compliance to vary with depth.

Compensation factors can be included in the correction function toaccount for instances when depth measurement errors are likely to occur.Typically, the or each compensation factor corresponds to a distance ordepth offset occurring at a known time (either the time of theconnection, or the time the direction of motion of the drill string isreversed).

A first example of a depth measurement error relates to the lengtheningof a drill string. As drilling progresses, lengths of pipe are added tothe drill string. This involves hanging the drill string from the rigfloor (referred to as “placing in slips”), disconnecting the mudcirculation, screwing a new length of pipe onto the existing pipe,reconnecting the mud circulation, and resuspending the drill string fromthe drawworks. In order to base a depth measurement on the number ofpipes suspended from the drawworks, a good estimate of the additionallength of pipe may be required. However, it is commonplace for errors tooccur at this stage, e.g. due to calibration errors or incorrecttabulation of the lengths of the pipes, and an error here will producean offset for all measurements made (in time) after the connection.

A second example is when the direction of drill string motion isreversed because of slack in the cable system.

Each of these types of error can be accounted for in the correctionfunction by introducing a single value compensation factor (e.g. aposition or depth offset) occurring at a known time (e.g. the time ofthe connection, or the time the direction of motion of the drill stringis reversed).

Generally the degree of correlation between the sets of logging datawill improve with complexity of the function. However, as the complexityof the function increases, the number of parameters which define thecompliance and which require determination during the correlation alsotends to increase, and at some point the process of correlation maybecome ill-conditioned.

The logging device may comprise two or more logging sensors (e.g. gammaray sensors or electrical resistivity sensors) spaced in the directionof device movement, the logging sensors generating respective logs oversubstantially the same time period. Preferably the spaced loggingsensors are of similar type so that the sensors respond in the samemanner to the well lithology. This improves the degree of correlationwhich can be obtained between the logging data. However, spaced sensorsof different type may also be used, although desirably these shouldreact sufficiently similarly to the well lithology.

The method may also be applied, however, to correlate sets of spatiallyoverlapping logging data generated by one logging device overnon-overlapping time periods. For example, during LWD a first set oflogging data may be generated as the drill bit extends the well, and aspatially overlapping second set of data may be generated as the drillbit is lifted off bottom.

The method of the invention discussed above may conveniently beimplemented in software, for execution on any appropriate digitalcomputer including one or more memory devices for storing the variousdata and one or more processors for executing the method.

Thus further aspects of the invention respectively provide a system(such as a computer or linked computers) operatively configured toimplement the method of the previous aspect of the invention; computerprogramming product or products (such as ROM, RAM, floppy discs, harddrives, optical compact discs, magnetic tapes, and othercomputer-readable media) carrying computer code for implementing themethod of the previous aspect of the invention; and a computer programper se for implementing the method of the previous aspect of theinvention.

For example, a further aspect of the present invention may provide asystem for correlating two or more overlapping well logs generated by awell logging device which, in use, is positioned in a well and ismounted to an elongate member extending along the well to the surface,movement of the elongate member at the surface controlling movement ofthe logging device along the well;

-   -   the system comprising:    -   a data storage device for storing (i) sets of logging data for        two or more spatially overlapping logs generated by the logging        device, each set comprising measures of a characteristic of the        well at longitudinally spaced positions along the well, and (ii)        measurement data for the period or periods of log generation,        the measurement data comprising measurements of the load on the        elongate member and measurements of the surface position of the        elongate member; and    -   a processor for correlating the sets of logging data by        determining an elongate member compliance which corrects the        positions of the measured well characteristics, the corrections        being performed on the basis of a correction function which        relates the position of the logging device to at least (i) the        measured load on the elongate member, (ii) the measured surface        position of the elongate member, and (iii) the compliance.

DESCRIPTION OF THE DRAWINGS

Embodiments of the invention will now be described by way of examplewith reference to the accompanying drawings in which:

FIG. 1 shows schematically a hydrocarbon well,

FIG. 2 is a flow diagram which shows the steps of the method of theinvention,

FIGS. 3 a and b respectively show uncorrected and corrected resistivitylogs obtained from a test well,

FIGS. 4 a and b respectively show uncorrected and corrected gamma raylogs obtained from a deep well, and

FIG. 5 shows corrected gamma ray logs for the test well of FIG. 3.

DETAILED DESCRIPTION

FIG. 1 shows schematically a hydrocarbon well. Drill string 58 is withinborehole 46 which is being cut by the action of drill bit 54. Drill bit54 is disposed at the far end of the bottom hole assembly 56 that isattached to and forms the lower portion of drill string 46. Bottom holeassembly 56 contains a number of devices includinglogging-while-drilling (LWD) subassemblies 60 which measure a wellcharacteristic or characteristics. Examples of typical LWD measurementsinclude downhole pressure (inside and outside the drill pipe),resistivity, density, and porosity.

The drilling surface system includes a derrick 68 and hoisting system, arotating system, a mud circulation system (not shown), and a blowoutpreventer 99. The hoisting system which suspends the drill string 58,includes draw works 70, hook 72 and swivel 74. The rotating systemincludes kelly 76, rotary table 88, and engines (not shown). Therotating system imparts a rotational force on the drill string 58 as iswell known in the art. The hoisting and rotating systems effectivelycontrol the movement of the drill bit and LWD subassemblies.

Although a system with a kelly and rotary table is shown in FIG. 1,those of skill in the art will recognize that the present invention isalso applicable to top drive drilling arrangements. Also, although thedrilling system is shown in FIG. 1 as being on land, those of skill inthe art will recognize that the present invention is equally applicableto marine environments.

The measurement signals from the LWD subassemblies are transmitted topulser assembly 64. Pulser assembly 64 converts the signals fromsubassemblies 60 into pressure pulses in the drilling fluid. Thepressure pulses travel upwards though the drilling fluid in the centralopening in the drill string and towards the surface. At the surface themud pulses are detected by a pressure pulse sensor 101 mounted on standpipe 96. The sensor 101 comprises a transducer that converts the mudpressure pulses into electronic signals. These signals are thenconverted into digital form and transmitted to storage system (e.g. ahard drive) 104 as well logs for subsequent analysis.

The skilled person would recognise, however, that other telemetrysystems, involving e.g. electrical transmission or acoustic wavepropagation, may be used to provide communication between the LWDsubassemblies and the surface.

While the LWD subassemblies are measuring downhole well characteristics,a surface load sensor 92 measures the hookload. The relative position ofthe hook, or other indicator of the surface position of the drillstring, is also measured. These measurements are transmitted to storagesystem 104 and stored for subsequent analysis. The processor 106 whichmay comprise multiple computer processing systems, is used to determinethe compliance in the drill string 58 and correct the stored logsaccording the description below.

Although a surface load sensor is shown, downhole load measurements maybe taken instead. For example, weight-on-bit measurements may be takenat subassemblies 60 and then transmitted to the surface using pulserassembly 64.

The method of the present invention is then used to correlateoverlapping well logs produced by the LWD subassemblies. The well logsmay overlap because the same well position has been traversed bydifferent longitudinally spaced sensors of the LWD subassemblies, orbecause the same sensor has traversed the same position more than onceas the drill string is raised and lowered in the borehole.

FIG. 2 is a flow diagram which shows the steps of the method, which maybe performed by a suitably programmed computer.

Firstly, at step 110 sets of logging data for the overlapping logs arereceived, and at step 120 hookload and surface position measurements arereceived for the period or periods of logging data generation. In step126 a compliance parameter is determined representing the compliance ofthe elongate member by comparing at least two of the sets of loggingdata depth corrected using a plurality of values for the complianceparameter, and selecting a value for the compliance parameter thatyields a high degree of consistency between the at least two sets oflogging data.

Then at step 130 the depth of at least one set of logging data measuredusing the logging system is depth corrected using a correction functionwhich relates the position of the logging system to at least (i) themeasured load on the elongate member, (ii) the measured surface positionof the elongate member, and (iii) the selected compliance parameter ofthe elongate member. The corrections are performed on the basis of acorrection function which is discussed in more detail below. Finally, instep 132 corrective action is taken based on the interpretation of thedepth corrected log. Examples of such correcting action include updatingan earth model and/or subsequent construction of the wellbore based onthe corrected log.

The correction function relates the position of the logging device tothe load on the elongate member, the surface position of the elongatemember, and the compliance or apparent compliance of the elongatemember. In simple embodiments this function may be of the form:D(t)=d(t)+λW(t)where D(t) is the corrected relative position of the logging device at aparticular instant t, d(t) is the corresponding relative surfaceposition of the elongate member (i.e. the uncorrected relative depth ofthe logging device), W(t) is the corresponding load on the elongatemember (e.g. the hook load or weight-on-bit when the elongate member isa drill string), and λ is the compliance of the elongate member.

Assuming there are two overlapping logs γ₁ and γ₂ produced by respectivesensors spaced a distance L apart in the direction of the well, then theproblem may be to find a value for λ such that the logs are optimallycorrelated. This can be done, for example, by optimising an appropriateobjective function. Thus the expectation value, E, may be minimised,where E is given by:E=<γ ₁(D ⁻¹(x))−γ₂(D ⁻¹(x−L))>,γ( ) being the measured value of the well characteristic from therespective log at a particular instant, D⁻¹( ) being the inverse of thecorrection function, and x being the relative position of the loggingdevice. An alternative would be to maximise the correlation coefficient,C, given by:$C = \frac{\left\langle {{\Upsilon_{1}\left( {D^{- 1}(x)} \right)}{\Upsilon_{2}\left( {D^{- 1}\left( {x - L} \right)} \right)}} \right\rangle}{\left\langle {\Upsilon_{1}\left( {D^{- 1}(x)} \right)} \right\rangle^{1/2}\left\langle {\Upsilon_{2}\left( {D^{- 1}\left( {x - L} \right)} \right)} \right\rangle^{1/2}}$

The analysis is the same when the overlapping logs are produced by thesame sensor at different time periods, except that compensation for thedistance, L, is not required (i.e. L=0).

The optimisation can be carried out numerically, e.g. by combiningglobal procedures (such as Monte-Carlo techniques or simulatedannealing) with local procedures (such as gradient descent). As a resultof this approach, an overall depth may be introduced, but this can beovercome by manually tying some points in the logs or by using thedeviation from a particular weight, W₀, rather than the absolute load,W, in the (inverse of the) correction function.

More generally the correction function may be of the form:${D(t)} = {{d(t)} + {{\Lambda(t)}\left( {{W(t)} - W_{0}} \right)} + {\sum\limits_{j}{C_{j}\left( {t - t_{j}} \right)}}}$where λ is the apparent compliance of the elongate member and (for theexample of a drill string) takes one value while sliding and anotherwhile rotating; t_(j) are times of events where depth errors may beintroduced such as (again for the example of a drill string)connections, lifting off bottom events, rotating to sliding transitions;and C_(j) are compensation factor constants for those errors.

Taking the example of a drilling operation in which the overlapping logsare obtained over a period which starts with rotating drilling, switchesto sliding and switches back to rotating drilling, and comes of bottomat each transition, there will be two λ values (one for rotation and onefor sliding) and two C_(j) constants (one for each transition) tooptimise.

Additionally the compliance may be allowed to change with depth toaccount for the lengthening of the drill string.

If the two logs derive from sensors of different type, the procedure foroptimising the correlation between the logs can still be followed.However, whereas for e.g. two gamma-ray logs produced by identicalsensors the only differences between them should be from noise so thathigh degrees of correlation should be obtained, with different sensorsresponding to the same lithology a lower degree of correlation should beexpected.

With more than two overlapping logs, the procedure can be made morerobust, at the expense of computational complexity. Instead ofoptimising objective functions, such as the expressions for theexpectation value and the correlation coefficient, which provide scalarvalues, it is possible to calculate the cross correlation matrix, M,between the logs μ. If each log is derived from a respective sensorspaced a respective distance L from a reference position on the loggingdevice, the value of each element of M is given by:M _(ij)=<μ_(i)(D ⁻¹(x−L _(i)))μ_(j)(D ⁻¹(x−L _(j)))>The optimised correlation is obtained when the ratio between the higherand lower eigenvalues of the matrix is maximised. Indeed, in the casewhere there are two logs, maximising this ratio is equivalent tomaximising the correlation coefficient, C.

The method can be further extended to a tool which makes a number ofmeasurements at different borehole azimuths at each of severallongitudinal positions along the tool. A known example of such a tool(an azimuthal resistivity tool) makes 56 azimuths at three longitudinalpositions. In this case, only measurements taken at differentlongitudinal positions whose azimuths align would be correlated, leadingto separate cross correlation matrices and sets of eigenvalues for eachof the 56 azimuths. The optimisation then involves the maximisation of afunction of the eigenvalue ratios of the respective matrices. Differentfunctions can be envisaged, such as the sum of the eigenvalue ratios orthe sum of the logarithms of the ratios.

In each of the various examples described above, the process ofcorrelating logs results in an optimal compliance for the elongatemember. This compliance may then be used to correct the depth of thelogging device which generated the logs by inserting the optimalcompliance back into the correction function.

We next show examples of logging data which has been correlated anddepth corrected using the method of the present invention.

FIG. 3 a shows three uncorrected resistivity graphs respectivelyobtained from three resistivity sensors spaced 12 inches (305 mm) apartalong a drill string. The depth scale is shown with respect to anarbitrary point.

The measurements were made in a shallow test well, so the requiredcorrection was only small (drill string compliance is roughlyproportional to length of drill string)—of the order of inches. However,the measurement resolution is such that corrections have a noticeableeffect on the graphs. A compliance was determined using the method ofthe present invention to maximise the correlation between the threegraphs. The compliance was then used to correct the depths of thegraphs. The corrected graphs are shown in FIG. 3 b. Notice in particularfor the region around 380 to 390 inches where the corrected logs showvery similar structure, and the lower two graphs overlie. In theuncorrected graphs the logs at this position are erratic. Also thefeatures at around 430 to 440 inches are significantly improved bycompliance correction.

FIG. 4 a shows four uncorrected logs derived from two gamma ray sensorsin a deep well. In this Figure lower depth values equal deepermeasurements. The lower sensor passed the same feature three times whileworking the pipe with different applied weights to provide three graphs.The upper sensor was deployed approximately 30 feet higher in the drillstring and provided only one graph. The raw sensor measurements weredepth averaged to form the logs.

A compliance for the drill string was again determined to maximise thecorrelation between and correct the depths of the four graphs. Thecorrected graphs are shown in FIG. 4 b. As a result of the correlation agamma ray feature at 99 feet is evident. Without depth correction, therewas little agreement on the position of this feature between the fourgraphs.

FIG. 5 shows unaveraged logs from a single gamma ray sensor in the testwell of FIG. 3 while respectively drilling ahead and pulling out. Thepoint density is higher for the drilling ahead log, as the drillingspeed was approximately one fifth of the speed of pulling out of hole.The data in both graphs was corrected with a compliance derived from theresistivity data shown in FIG. 3. Additionally, however, a compensationfactor was used to apply an offset correction for the transition betweendrilling ahead and pulling out. The offset correction was derived bymaximizing the correlation of the gamma ray data between drilling aheadand pulling out.

While the invention has been described in conjunction with the exemplaryembodiments described above, many equivalent modifications andvariations will be apparent to those skilled in the art when given thisdisclosure. Accordingly, the exemplary embodiments of the invention setforth above are considered to be illustrative and not limiting. Variouschanges to the described embodiments may be made without departing fromthe spirit and scope of the invention.

1. A method of correcting depth of logging data measured by a loggingsystem mounted on an elongate member extending through a wellbore to thesurface comprising the steps of: (a) receiving sets of logging data fortwo or more spatially overlapping logs generated by the logging system,each set comprising measures of a characteristic associated with thewellbore at longitudinally spaced positions along the wellbore; (b)receiving measurement data for the period or periods of log generation,the measurement data comprising measurements of the load on the elongatemember and measurements of the surface position of the elongate member;(c) determining a compliance parameter representing the compliance ofthe elongate member by comparing at least two of the sets of loggingdata depth corrected using a plurality of values for the complianceparameter, and selecting a value for the compliance parameter thatyields a high degree of consistency between the at least two sets oflogging data; and (d) correcting the depth of at least one set oflogging data measured using the logging system, using a correctionfunction which relates the position of the logging system to at least(i) the measured load on the elongate member, (ii) the measured surfaceposition of the elongate member, and (iii) the selected complianceparameter of the elongate member.
 2. A method according to claim 1,wherein the elongate member is a drill string.
 3. A method according toclaim 2 wherein in performing step (c) the at least two of the sets oflogging data are measured over a period or periods of time during whichno sections of the elongate member have been added or removed.
 4. Amethod according to claim 1 wherein in step (c) the value of thecompliance parameter selected is one wherein the degree of consistencyis maximized or the degree of difference is minimized between the atleast two sets of logging data.
 5. A method according to claim 1 whereinin step (c) the correction function further includes a depth offset forall measurements made after a time in which a depth error is believed tohave occurred.
 6. A method according to claim 5 wherein a depth error isbelieved to have occurred when adding or removing sections of theelongate member.
 7. A method according to claim 5 wherein a depth erroris believed to have occurred when the direction of longitudinal motionof the elongate member changes polarity.
 8. A method according to claim5 wherein a depth error is believed to have occurred when rotationalspeed of the elongate member changes between stationary and rotating. 9.A method according to claim 1 wherein step (c) is performed separatelyfor data collected while sliding and rotating.
 10. A method according toclaim 1, wherein the logging system comprises two or more loggingsensors spaced in the direction of device movement, each logging sensorgenerating at least one of the logs.
 11. A method according to claim 1,further comprising the step of (e) taking action based on the loggingdata corrected in step (d).
 12. A system for correcting depth of loggingdata measured by a logging system mounted on an elongate memberextending through a wellbore to the surface comprising: a data storagedevice for storing (i) sets of logging data for two or more spatiallyoverlapping logs generated by the logging system, each set comprisingmeasures of a characteristic associated with the wellbore atlongitudinally spaced positions along the wellbore, and (ii) measurementdata for the period or periods of log generation, the measurement datacomprising measurements of the load on the elongate member andmeasurements of the surface position of the elongate member; and aprocessor adapted to (i) determine a compliance parameter representingthe compliance of the elongate member by comparing at least two of thesets of logging data depth corrected using a plurality of values for thecompliance parameter, and selecting a value for the compliance parameterthat yields a high degree of consistency between the at least two setsof logging data, and (ii) correct the depth of at least one set oflogging data measured using the logging system, using a correctionfunction which relates the position of the logging system to at least(i) the measured load on the elongate member, (ii) the measured surfaceposition of the elongate member, and (iii) the selected complianceparameter of the elongate member.
 13. A system according to claim 12wherein the processor is further adapted such that when determining thecompliance parameter the at least two of the sets of logging data aremeasured over a period or periods of time during which no sections ofthe elongate member have been added or removed.
 14. A system accordingto claim 12 wherein in the processor is further adapted to select thevalue of the compliance parameter such that the degree of consistency ismaximized or the degree of difference is minimized between the at leasttwo sets of logging data.
 15. A system according to claim 12 wherein theprocessor is further adapted such that the correction function furtherincludes a depth offset for all measurements made after a time in whicha depth error is believed to have occurred.
 16. A system according toclaim 12 wherein the processor is further adapted to determine aseparate compliance parameter for data collected while sliding and whilerotating.